Chemically enhanced thermal recovery of heavy oil

ABSTRACT

Described herein are methods for removing heavy oils from underground reservoirs. The methods involve the use of chemical compositions in combination with steam techniques for the efficient removal of heavy oils.

BACKGROUND OF THE INVENTION

Heavy oil sand, such as tar sand, is a major source of petroleum. Heavyoil-containing reservoirs, however, contain crude petroleum or bitumenof such high viscosity that it cannot be recovered by conventionalpetroleum recovery techniques. However, once the crude petroleum orbitumen is recovered, surface-milling processes can separate the bitumenfrom sand. The separated bitumen may be converted to light hydrocarbonsusing conventional refinery methods.

Steam has long been used in the recovery of oil from these heavyoil-containing reservoirs. For example, thermal recovery techniques suchas cyclic steam simulation (CSS), Huff and Puff, and Steam AssistedGravity Drainage (SAGD) have been used. Although these techniques havehigh recovery yields, their energy efficiency is poor.

Another approach involves enhanced oil recovery (EOR) techniques. Theseprocesses involve the use of surfactants in the presence of alkalisolutions and salts to reduce the oil-water interfacial tension andalter the wettability of the reservoir rock, which ultimately results inenhanced recovery. In these processes, the temperature is usually below80° C., which can limit the recovery of the heavy oils due to their highviscosity. The main objective of thermal recovery techniques is toreduce the heavy oil viscosity by increasing the temperature.

Thus, what is needed are enhanced oil recovery techniques that can beperformed at the elevated temperatures typically used in steamapplications to further increase or maintain the recovery yields bychemical means, but reduce the energy spent on recovery of heavy oils.

BRIEF SUMMARY OF THE INVENTION

Described herein are methods for removing heavy oils from undergroundreservoirs. The methods involve the use of chemical compositions incombination with steam techniques for the efficient removal of heavyoils. The advantages of the materials, methods, and articles describedherein will be set forth in part in the description which follows, ormay be learned by practice of the aspects described below. Theadvantages described below will be realized and attained by means of theelements and combinations particularly pointed out in the appendedclaims. It is to be understood that both the foregoing generaldescription and the following detailed description are exemplary andexplanatory only and are not restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying Figures, which are incorporated in and constitute apart of this specification, illustrate several aspects described below.

FIGS. 1A-1D are schematics of different capillary phenomena inreservoirs.

FIGS. 2A and 2B show steam flux driven liquid flow (SFDLF) in areservoir capillary, where there is a coupling between the steam andliquid flow.

FIG. 3 shows another form of SFDLF in a reservoir capillary.

DETAILED DESCRIPTION OF THE INVENTION

Before the present materials, articles, and/or methods are disclosed anddescribed, it is to be understood that the aspects described below arenot limited to specific compounds, synthetic methods, or uses, as suchmay, of course, vary. It is also to be understood that the terminologyused herein is for the purpose of describing particular aspects only andis not intended to be limiting.

In this specification and in the claims that follow, reference will bemade to a number of terms that shall be defined to have the followingmeanings:

Throughout this specification, unless the context requires otherwise,the word “comprise,” or variations such as “comprises” or “comprising,”will be understood to imply the inclusion of a stated integer or step orgroup of integers or steps but not the exclusion of any other integer orstep or group of integers or steps.

It must be noted that, as used in the specification and the appendedclaims, the singular forms “a,” “an” and “the” include plural referentsunless the context clearly dictates otherwise. Thus, for example,reference to “an oil” includes a single oil or mixtures of two or moreoils.

“Optional” or “optionally” means that the subsequently described eventor circumstance may or may not occur, and that the description includesinstances where the event or circumstance occurs and instances where itdoes not.

Described herein are methods for removal of heavy oils from undergroundreservoirs. The term “heavy oil” is any source or form of viscous oil.For example, a source of heavy oil includes tar sand. Tar sand, alsoreferred to as oil sand or bituminous sand, is a combination of clay,sand, water, and bitumen. The thermal recovery of heavy oils is based onthe viscosity decrease of fluids with increasing temperature. Once theviscosity is reduced, the mobilization of fluids by steam, hot waterflooding, or gravity is possible. The reduced viscosity makes thedrainage quicker and therefore directly contributes to the recoveryrate.

The recovery rate is dependent on the drainage rate, which is controlledby the characteristics of multiphase flow (heavy oil and hot water) inporous media. Emulsion formation can severely limit the drainage ratewhen the droplet size is comparable to the pore size. One way to avoidthis problem involves the formation of microemulsions having a dropletsize is much smaller (20 nanometers) than the characteristic pore sizeof heavy oil reservoirs. A microemulsion phase can be in equilibriumwith an organic phase, an aqueous phase, or simultaneously both anorganic and an aqueous phase. The latter type of microemulsion phase,which can be found in Winsor III type systems, is known as a middlephase microemulsion. It has low viscosity, and is therefore beneficialfor EOR or steam-assisted heavy oil recovery.

The contributing factors reducing recovery of heavy oils at elevatedtemperatures involve unfavorable wetting properties of the solid matrixand the high interfacial tension between the organic and aqueous phases.This is depicted in FIG. 1. The oil 10 is trapped in a narrow capillary11 when the gravitational and hydrodynamic driving forces of water 12cannot overcome the resisting capillary forces (see FIG. 1A). TheLaplace pressure difference keeps the oil phase trapped in thecapillaries. When the oil-water interfacial tension is sufficientlyreduced, most of the trapped oil can be removed (see FIG. 1B). The oilcan also be trapped (due to the Laplace pressure difference) when thereare narrow passes in the capillaries, even in the case of water-wetreservoir 13 (see FIGS. 1C and 1D). High oil-water interfacial tensioncan also prevent the release of the organic phase from dead capillaryends. Additionally, variable permeability distribution (most of theMcMurray formation in Alberta, Canada) also affects the trapping forces.

The methods described herein facilitate the recovery of heavy oils. Forexample, the methods reduce the oil-water interfacial tension andimprove the mobility of heavy oils due to either microemulsion formationor the formation of emulsions having low interfacial tension using steamtechniques (e.g., SAGD or CSS operations). Additionally, the methodsdescribed herein alter the wetting properties of the solid matrix thatentraps the heavy oil. By reducing the viscosity and increasing themobility of heavy oils, several advantages can be achieved, including,but not limited to, increased oil production rate, increased steamchamber dimensions resulting in reduced well density, reduced lifecycle, and a reduction in residual oil after the total life cycle of theoperation.

In one aspect, the method comprises: injecting into the reservoir (i)steam, (ii) an alkaline compound, (iii) a nonionic surfactant, and,optionally, (iv) an alcohol; and removing the oil from the reservoir.

In another aspect, the method comprises: injecting into the reservoir(i) steam, (ii) an alkaline compound, (iii) an acid, and, optionally,(iv) an alcohol; and removing the oil from the reservoir.

In a further aspect, the method comprises: injecting into the reservoir(i) steam, (ii) an ionic surfactant, and, optionally, (iii) an alcohol;and removing the oil from the reservoir.

In a further aspect, the method comprises: injecting into the reservoir(i) steam, (ii) a mixture comprising an ionic surfactant and a nonionicsurfactant, and, optionally, (iii) an alcohol; and removing the oil fromthe reservoir.

In a further aspect, the method comprises: injecting into the reservoir(i) steam, (ii) an alcohol, and, optionally, (iii) an alkaline compound.

Steam techniques known in the art for removing heavy oils can be usedherein. In general, steam is injected into the underground reservoirthereby heating the reservoir to mobilize and recover at least afraction of reservoir hydrocarbons and to form a steam chamber in thereservoir. There is continuous steam condensation on the steam chamberboundaries. The condensation heat increases the temperature resulting ina viscosity drop of the heavy oil trapped in the reservoir. Next,chemical additives are introduced into the injection well, which is theinput point to the steam chamber, either periodically or continuously.The injection can be made at the surface wellhead or deep in thereservoir with additional tubing (e.g., coiled tubing) inserted into theinjection well. The oil may be recovered in a production well separatefrom the injection well.

When selecting chemical additives, the elevated temperatures used in thesteam processes must be considered. For example, the temperature canreach as high as 350° C. using SAGD, although this temperature can varydepending on the crude oil and reservoir properties. The residence timeof the applied chemicals in the different temperature zones of thereservoir has a major influence on the selection as well, because thetemperature and the residence time together determine the thermalstrain. Since the residence time in the reservoir is orders of magnitudelonger than that in the injection well, the reservoir conditions must beprimarily considered. At steam flooding, reservoir temperatures measuredin observation wells for three different fields in California, USA were120, 160, and 180° C. (K. C. Hong, Steamflood Reservoir Management,PenWell, 1994, pages 386, 387, and 390). In the case of CSS, thetemperature begins at 345° C., but after a period of time thetemperature can be decreased from 85 to 100° C. Therefore, the thermalstability of the chemical additives can be relaxed to some extent whenCSS is employed. In one aspect, the chemical additives are stable attemperatures greater than 200° C. Additionally, the chemical additivesgenerally possess high vapor pressures. The high vapor pressurefacilitates the delivery of the additives into the reservoir. As will bediscussed below, additives that do not possess high vapor pressures canbe formed in situ from high vapor pressure compounds. Thus, additivesthat are thermally stable and have a sufficiently high vapor pressureare “compatible” with the steam and useful herein. In cases where thevapor pressure of additives is low and not “compatible” with steam, theadditives can be injected in the form of a liquid, aerosol, orsuspension.

In one aspect, the chemical additives injected into the reservoircomprise an alkaline compound, a nonionic surfactant, and, optionally,an alcohol. The alkaline compound is any compound that can increase thepH of the steam and the reservoir. An increase in pH facilitates therelease of natural surfactants present in heavy oils. These surfactantscan reduce the oil-water interfacial tension. Additionally, reducedviscoelasticity of the oil-water interfaces has been observed at high pHwhich may be due to the released, naturally-occurring, surfactants.

In one aspect, the alkaline compound comprises an amine, such as aprimary amine, a secondary amine, or a tertiary amine that is compatiblewith steam, or any combination of such amines. In another aspect, thesteam-compatible alkaline compound is ammonia. In yet another aspect,the alkaline compound is an alkaline metal hydroxide, alkaline metalcarbonate, alkaline metal hydrocarbonate, or ammonium carbonate, or anycombination thereof, which compounds are not compatible with steam.

The amount of alkaline compound is sufficient to raise the pH of thesteam to greater than 7, greater than 8, greater than 9, greater than10, greater than 11, or greater than 12. Depending upon the selection ofthe alkaline compound, the compound can be introduced into the steam asa gas, a liquid, or a liquid solution of either gas, liquid, or solid.As well, the alkaline compound can be introduced into the steam as aliquid, a suspension of a solid, or as an aerosol. Additionally, thecompound can be introduced in the form of a supercritical fluid whereeither the compound itself forms the supercritical fluid or the compoundis one of the components of the supercritical fluid.

The nonionic surfactants, which generally have a higher vapor pressurethan ionic surfactants (e.g., low molecular weight acetylenicsurfactants), alter the wetting properties of the solid matrix. Incertain aspects, when the nonionic surfactant is used in combinationwith an alcohol, which is a co-surfactant, the oil-water interfacialtension can approach zero. In this situation, microemulsions can beformed. Salts are often used in these formulations to achieve minimuminterfacial tension. As described above, microemulsions can facilitatethe removal of heavy oil. Examples of nonionic surfactants useful hereininclude, but are not limited to, an alkyl, aryl, or alkylaryl (ethyleneoxide); an alkyl, aryl, or alkylaryl poly (propylene oxide); an alkyl,aryl, or alkylaryl poly (propylene and ethylene oxide) block polymer; analkoxylated amine or diamine; a polyetherpolyol; a block polymer ofcarbonyldiamide polyoxyalkylated glycol; an alkylarylpolyethoxyethanol;an N-betaine (e.g., dodecyl N-betaine); a C-betaine (e.g., dodecylC-betaine); an amine oxide (e.g., decyl dimethyl amine oxide); aphosphine oxide (e.g., decyl dimethyl phosphine oxide); a sulfinil-ol(e.g., decyl sulfinylethanol); an ammonio carboxylate or sulfonate(e.g., decyl dimethylammoniopropane sulfonate); a sugar alkylate (e.g.,alpha-D-glucosyl octane); a polyol ether (e.g., octyl beta D glucoside);an oxyethylene sorbitan; a sarcosinate (e.g., lauryl sarcosine); anacetylenic surfactant; an ethoxylated alkanolamide; an alkyl amine; analkyl imidazoline; a poloxamer; an alkyl polyglucoside; a fatty alcohol,or any combination thereof. With respect to the alcohol, the alcoholcomprises a C₄ to C₉ alcohol. The alcohol can be branched or straightchain.

Nonionic surfactants or amines can typically be dissolved in aliphaticor aromatic hydrocarbons or in their mixtures, so these organic solventsare included in the delivered composition. The presence of these organicsolvents can have an additional synergetic effect on oil recovery.

In another aspect, the chemical additives comprise an alkaline compound,an acid, and, optionally, an alcohol. In this aspect, an ionicsurfactant is produced in situ when the alkaline compound reacts withthe acid. The alkaline compound and the acid may be alternately injectedinto the reservoir. The alkaline compounds described above can be usedin this aspect. In one aspect, the acid is an organic acid, whichincludes alkyl carboxylic acids, aryl carboxylic acids, cycloalkylcarboxylic acids, and aromatic and alicyclic carboxylic acids, or anycombination thereof. The term organic acid also includes compoundspossessing groups that can be converted to carboxylic acids. Examples ofsuch compounds include, but are not limited to, amides, anhydrides,nitriles, and alcohols that can be converted to a carboxylic acid insitu during injection into the reservoir with the steam. Alternatively,the organic acid can be a polymer possessing a plurality of carboxylicacid groups.

In one aspect, the organic acid comprises a saturated fatty acid, anunsaturated fatty acid, or a combination thereof. Examples of fattyacids useful herein include, but are not limited to, butyric acid,caproic acid, caprylic acid, capric acid, lauric acid, myristic acid,palmitic acid, stearic acid, arachidic acid, behenic acid, myristoleicacid, palmitoleic acid, oleic acid, linoleic acid, alpha-linolenic acid,eicosapentaenoic acid, erucic acid, docosahexaenoic acid, arachidonicacid, or any combination thereof. Other examples of acids useful hereininclude, but are not limited to, an alkyl sulfonic acid, an arylsulfonic acid, an alkylaryl sulfonic acid, a sulfo carboxylic acid, analkyl naphthalene sulfonic acid, an olefinic sulfonic acid, apolycarboxylic acid, a sulfo carboxylic acid, a phosphono carboxylicacid, a thiosulfonic acid, or any combination thereof.

In another aspect, the chemical additives comprise an ionic surfactantand, optionally, an alcohol. A mechanism that can transport ioniccompounds in the steam chamber despite their negligible vapor pressureis described below and depicted in FIG. 2. When saturated steam passesthrough the pores, a water film 20 forms on the surface of the pores(depicted as solid matrix 21 in FIG. 2). The steam transport 22 launchesa liquid transport in the water film 20 (FIG. 2A). As the path narrows(i.e., constriction of the solid matrix 21), a multiphase flow of water20 and steam 22 can occur (FIG. 2B). Therefore, ionic compounds can havea finite transport rate within the steam chamber via moving wettingliquid films on the capillary surfaces.

Turning to FIG. 3, in the presence of surface-active additives, thewettability of the solid matrix 21 increases and the formation ofaqueous lamellas 31 formed from the water-film 20 can occur. Thelamellas will travel with the speed of the steam 22, which increases thesteam flux driven liquid flow (SFDLF) considerably. Thus, ioniccompounds can travel through the pores of the solid matrix in the formof a steam foam and remove heavy oils from the matrix.

The alcohols described above can be used in this aspect. In one aspect,the ionic surfactant comprises an anionic, cationic, amphoteric, orpolymeric surfactant(s). Examples of anionic surfactants include, butare not limited to, sulfates, sulfonates, and carboxylates. The ionicsurfactants can be naturally-occurring or synthetic. Sulfonatescontaining the C—S bond are more stable chemically than the C—O—S bondof the sulfates or the C—O—P bond of the phosphates. Thus, sulfonatesand carboxylates are more stable to hydrolysis and extreme pH levelscompared to sulfates and phosphates.

In one aspect, the anionic surfactant comprises an alkyl sulfate salt(e.g., sodium dodecyl sulfate, ammonium lauryl sulfate), an alkyl ethersulfate (e.g., sodium lauryl ether sulfate), an alkyl benzene sulfonate,or any combination thereof. In another aspect, the sulfonate comprisessulfonates of petroleum, oil and fatty acids, alkylaryls, α-olefins,benzene, toluene, xylene, condensed naphtolenes, dodecyl andtridecylbenzenes, naphthalene, and alkyl napthalenes. In yet anotheraspect, the anionic surfactant comprises sulfosuccinates, sulfocarboxylates, alkyl naphthalene sulfonates, olefinic sulfonates, fattyacid sulfonates, polycarboxylates, sulfo carboxylates, phosphonocarboxylates, thiosulfates.

Examples of useful cationic surfactants include, but are not limited to,a quaternary ammonium salt, an amine salt, an imidazoline salt, abetaine (e.g., octyl C-betaine hydrochloride or dodecyl N-betainehydrochloride), a pyridinium derivative (e.g., dodecyl pyridiniumchloride), or any combination thereof. A variety of differentcounterions can be used with the ionic surfactants, including alkalimetal ions, alkaline earth metal ions, halides, nitrates, andcarboxylates. Generally, the counterions are soluble in water.

In surfactant-containing systems, alcohols are considered to beco-surfactants, which enhance the performance of surfactants. Oneapplication of co-surfactants is the application of alcohols inmicroemulsion systems where the zero interfacial tension condition isoften approached. A manifestation of the beneficial contribution ofalcohol presence in microemulsion systems is the formation of highlyflexible interfaces. This is one of the targeted areas of enhancedrecovery of heavy oils by steam assisted techniques. Due to thesebeneficial effects, alcohols can be considered as part ofsurfactant-containing additives. For heavy oil systems, in which theconcentration of natural surfactants could be considerable, theapplication of alcohols as additives to enhance recovery can also bebeneficial, even in cases when no artificial surfactant is added. Inthese cases, the alcohol behaves as the co-surfactant of naturalsurfactants.

The chemical additives described above can be injected into thereservoir in any sequence, concurrently with, or separate from, thesteam. For example, the chemical additives can be admixed prior toinjection into the steam. In one aspect, the additives can besimultaneously injected with the steam in order to ensure or maximizethe amount of additives moving with the steam. In some instances it maybe desirable to precede or follow a steam-additive injection stream witha steam-only injection stream. Alternatively, the additives can beintroduced into the steam sequentially. In certain aspects, theadditives are introduced alternatively into the steam. For example, theorganic acid and alkaline compound (e.g., ammonia) can be alternativelyintroduced into the steam. The additives can be introduced continuouslyor periodically into the steam. The particular steam temperature andpressure actually used in the process will depend on such specificreservoir characteristics as depth, temperature, and oil viscosity, andthus will be worked out for each reservoir.

In certain aspects, it is desirable to inject the chemical additives asan aerosol or spray so that the chemicals do not remain at the bottom ofthe injection well. In this aspect, the chemical additives are carriedinto the reservoir rock containing heavy oils by the steam. Thus, thechemical additives are pushed deep into the pores of the reservoir rock,which ultimately facilitates the release and isolation of heavy oils.The use of aerosols prevents the chemical additives from being directedtoward the production well instead of the upper walls of the steamchamber, which is desired. Techniques known in the art for producing anddelivering aerosol formulations can be used herein. In one aspect,carbon dioxide can be used to make the aerosol spray. Carbon dioxide cancondition the reservoir and increase the effectiveness of the methodsdescribed herein for removing heavy oils from the reservoir. Carbondioxide also lowers the minimum miscibility pressure of the reservoir,which can enhance the recovery of heavy oil. The use of carbon dioxideto facilitate the removal of oil is disclosed in U.S. Pat. Nos.5,358,052; 6,988,552; and 4,513,821, which are incorporated herein byreference.

Other additives can be used in combination with any of the additivesdescribed above. In one aspect, a chelating agent can be used. Chelatingagents known in the art can be used to dissolve carbonates, minerals,and clays in order to create wormholes and other passageways withoutcompromising the structure of the reservoir. The formation of thesepassageways can facilitate the injection of steam and the chemicaladditives into the reservoir, which will increase heavy oil removal. Inone aspect, chelating acid includes a polycarboxylic acid, maleic acid,tartaric acid, citric acid, NTA (nitrilotriacetic acid), HEIDA(hydroxyethyliminodiacetic acid), HEDTA(hydroxyethylethylenediaminetetraacetic acid), EDTA(ethylenediaminetetraacetic acid), CyDTA(cyclohexylenediaminetetraacetic acid), DTPA(diethylenetriaminepentaacetic acid), ammonium salts thereof, lithiumsalts thereof, sodium salts thereof, and/or mixtures of these acidsand/or their partially or completely neutralized salts, with the same ordifferent metal ions. The use of these chelating agents is disclosed inU.S. Pat. Nos. 6,911,418 and 6,436,880, which are incorporated herein byreference. The concentration of the chelating agent can vary dependingupon the selection of chemical additives and the nature of the heavy oilreservoir. In one aspect, the concentration of the chelating agent is upto 50 percent by weight of the chemical additives injected into thereservoir. The chelating agent can be injected into the reservoir asneeded in order to increase the permeability and heat conductivity ofthe reservoir. Thus, the chelating agent can be injected periodically orcontinuously.

In another aspect, one or more polymers that prevent water blocks in theinjection and production lines can be used. Examples of such polymersinclude, but are not limited to, fluoropolymers, telomers, andfluorosilanes. By preventing water blocks in the lines, increasedinjection rates of steam and chemical additives are possible.

The additional additives can be added at different stages of theprocess. For example, the additives can be injected into the reservoirprior to injection of the other chemical additives. Alternatively, theadditives can be added concurrently while the chemical additives andsteam are introduced into the reservoir. The amounts of the additionaladditives can vary depending upon processing conditions.

The amount of chemical additives used to remove the heavy oil can varydepending upon the selection of the additives, processing conditions(e.g., rates of injection and temperature of steam), and the depth andcomposition of the reservoir. In one aspect, the amount of chemicaladditives (e.g., surfactant) is sufficient to produce an oil/waterinterfacial tension less than 0.3 milliNewton/meter, less than 0.2milliNewton/meter, or less than 0.1 milliNewton/meter. In anotheraspect, the chemical additives are present in a sufficient amount toproduce a microemulsion of heavy oil, where the droplet size is lessthan 20 nanometers. In other aspects, the chemical additives can be inthe form of a microemulsion prior to injection into the reservoir. Atthis application the addition of organic solvent is needed. Aliphatic oraromatic hydrocarbons or their mixtures can be used as organic solvents.As described above, the presence of these organic solvents can have anadditional synergetic effect on oil recovery. In a further aspect, whenthe chemical additives comprise a combination of ionic and nonionicsurfactant and, optionally, an alcohol, the amount of additives issufficient to increase the SFDLF delivery mechanism described above.

In a further aspect, steam, an alcohol, and, optionally, an alkalinecompound are injected into the reservoir.

After the heavy oil is removed from the reservoir as an oil-in-water orwater-in-oil emulsion (e.g., a microemulsion), the emulsion isdemulsified to isolate the heavy oil. Any conventional method may beused above ground for demulsifying the heavy oil-water emulsion andseparating the heavy oil from water and sand. Demulsification can occurat or below the earth's surface. For example, the heavy oil-wateremulsion may be processed by settling to remove sand; dehydration,chemical, thermal, or electrical treatment; filtration, centrifuging,and various combinations thereof. The separated heavy oil serves as araw material for the production of various petroleum products includingheavy crude, asphalt, tar, solvents, and gases. The separated waterstream can be upgraded by conventional methods, heated, and recycled tothe injection well as wet steam or hot water.

Throughout this application, various publications are referenced. Thedisclosures of these publications are incorporated in their entiretiesby reference into this application in order to more fully describe thecompounds, compositions, and methods described herein.

Various modifications and variations can be made to the compounds,compositions, and methods described herein. Other aspects of thecompounds, compositions, and methods described herein will be apparentfrom consideration of the specification and practice of the compounds,compositions, and methods disclosed herein. It is intended that thespecification and examples be considered as exemplary.

1-12. (canceled)
 13. A process for removing heavy oil from anunderground heavy oil reservoir, comprising: injecting into thereservoir (i) steam, (ii) an alkaline compound, and (iii) an acid; andremoving the oil from the reservoir. 14-25. (canceled)
 26. The processof claim 13, further comprising injecting into the reservoir an alcohol.27. The process of claim 13, wherein the alkaline compound and the acidare alternately injected into the reservoir
 28. The process of claim 13,wherein an ionic surfactant is produced in situ in the reservoir whenthe alkaline compound reacts with the acid.
 29. The process of claim 13,wherein the alkaline compound is introduced into the steam as a gas, aliquid, or a solution of either gas, liquid, or solid.
 30. The processof claim 13, wherein the alkaline compound is introduced into the steamas a suspension of a solid, or an aerosol.
 31. The process of claim 13,wherein the alkaline compound is introduced into the steam as asupercritical fluid or a component of a supercritical fluid.
 32. Theprocess of claim 13, wherein the alkaline compound comprises a primary,secondary, or tertiary amine that is compatible with steam, or anycombination of such amines.
 33. The process of claim 13, wherein thealkaline compound is ammonia.
 34. The process of claim 13, wherein thealkaline compound is an alkaline metal hydroxide, alkaline metalcarbonate, alkaline metal hydrocarbonate, ammonium carbonate, or anycombination thereof.
 35. The process of claim 13, wherein the acid is anorganic acid.
 36. The process of claim 35, wherein the organic acid isan alkyl carboxylic acid, an aryl carboxylic acid, a cycloalkylcarboxylic acid, an aromatic carboxylic acid, an alicyclic carboxylicacid, or any combination thereof.
 37. The process of claim 35, whereinthe organic acid comprises compounds possessing groups that can beconverted to carboxylic acids.
 38. The process of claim 37, wherein thecompounds comprise an amide, an anhydride, a nitrile, or an alcohol thatcan be converted to a carboxylic acid in situ during injection into thereservoir with the steam.
 39. The process of claim 35, wherein theorganic acid is a polymer possessing a plurality of carboxylic acidgroups.
 40. The process of claim 35, the organic acid comprises asaturated fatty acid, an unsaturated fatty acid, or a combinationthereof.
 41. The process of claim 40, wherein the saturated fatty acidis butyric acid, caproic acid, caprylic acid, capric acid, lauric acid,myristic acid, palmitic acid, stearic acid, arachidic acid, behenicacid, myristoleic acid, palmitoleic acid, oleic acid, linoleic acid,alpha-linolenic acid, eicosapentaenoic acid, erucic acid,docosahexaenoic acid, arachidonic acid, or any combination thereof. 42.The process of claim 13, wherein the acid is an alkyl sulfonic acid, anaryl sulfonic acid, an alkylaryl sulfonic acid, a sulfo carboxylic acid,an alkyl naphthalene sulfonic acid, an olefinic sulfonic acid, apolycarboxylic acid, a sulfo carboxylic acid, a phosphono carboxylicacid, a thiosulfonic acid, or any combination thereof.